Description of Flow Model

Shale gas is one of the most rapidly growing forms of natural gas. It will make a major

contribution to future world gas production. These are the complex rocks characterized

by heterogeneity in structure and composition in all scales. However, understandings

and technologies needed for effective development of these resources are still lacking

and as a result, we have low gas recovery. There have been numerous approaches to

12 model the gas production from the reservoirs from advanced simulators to analytical solutions.

Moreover, long term shale gas well performance characteristics are generally not well understood. The extremely low permeability of shale reservoirs gives steady and continuous presence of pressure transient effects during well production. This makes production forecasting a difficult and non-unique exercise. In this thesis, we present a straight forward methodology to explain the characteristics of well performance by modelling gas production in a new innovative way.

Gas in shale reservoirs is present both in the naturally occurring micro fractures and adsorbed onto the surface of the shale grains. By storing gas in a dense, liquid-like adsorbed phase, the overall storage capacity of the rock is increased relative to if there were a free gas phase alone. Moreover, the release of this adsorbed phase is pressure dependent. As a reservoir is depleted, the adsorbed phase is freed, providing not just additional gas for production but helping to maintain pressure (and perhaps open pore throats for fluid flow) as well. While adsorption allows for larger quantities of gas to be in place and possibly produced, factors such as desorption pressure, kinetics, and alteration of effective stresses makes it difficult to know if desorbed gas will contribute significantly to production.

Gas production from this tight shale deposits are made possible by extensive and deep well fracturing which contacts large fractions of the formation. Production of gas takes place by diffusion of adhered gas in the matrix and by Darcy type flow in the fractures.

The model presented here can be divided into three stages:

1. Firstly, we look into the model of one cell of the reservoir . In this work, we

develop a flow model with a cell in the shape of a cube and a sphere inside it. The

gas in stored in natural fractures, pores and adsorbed onto kerogen/organic

matter. When the production starts, free gas from the natural fractures is

produced first and then the matrix feed the fracture network and matrix is in

turn fed by adsorbed gas on kerogen or organic matter exposed inside the

nanopores. Matrix here means both the organic matter or kerogen and the

inorganic matter. However, the inorganic matter have much bigger pores and

they can be classified as micro-fractures. These micro-fractures becomes active

13 after hydraulically fracturing the formation. Thus, it is convenient to define pore space inside the organic matter as matrix and that of in the inorganic matter as micro-fractures.

In this thesis for the ease of modelling, we assume all the kerogen bulk or organic matter to be located at one place, i.e., inside the sphere. Thus, the amount of adsorbed gas is present only inside the sphere as shown in figure 2.1. Whereas, the space outside of sphere and inside the cube consists of inorganic matter with micro-fractures where free gas is stored. In actual reservoir, the organic matter is much more dispersed throughout the inorganic matter but this assumption is to efficiently model the gas production.

Figure 2.1 3D representation of single cell used in FSGP model.

As the gas is produced first from the micro-fractures, the decrease in pressure in the cell will trigger desorption of gas from the organic matter or the surface of kerogen. After desorption, surface area are available for gas to diffuse from kerogen. This diffused gas gets adsorbed onto the available surface of kerogen.

When the adsorbed gas is released, it will firstly act as free gas within the

kerogen pores within the sphere. This free gas will act like a gas source and feed

gas to the micro-fractures in the cube. The flow in network is considered to be

linear Darcy’s flow. This shows the extent of gas transport in shale gas

reservoirs.

14 The sphere can be considered consisting of many layers of adsorbed gas. With pressure decline, the gas will be desorbed first from the outer most layer of sphere which will cause decrease in molecular concentration of gas. The available surface area and change in concentration will trigger the diffusion of gas from kerogen. The process will continue to all the layers present internally until all the gas diffuses out of the kerogen, absorbed onto available surface area and is desorbed into the micro-fractures in the cube.

Figure 2.2 illustrates schematic of the outward gas flow from the surface of the organic matter towards the network of fractures where gas flow occurs. The direction of diffusion here is in the direction of increasing radius, r. Assuming that the outer surface of the organic matter or sphere remains constant during the flow due to the gas desorption that takes place internally. The concentration in the outer layer will only change when all the gas is desorbed from the inner layers. Also, we assume that the concentration of gas in the micro-fracture remains constant once desorption of gas starts from the sphere. The amount of gas adsorbed in the sphere is given by Langmuir’s Isotherm which is discussed in detail later. Figure 2.3 gives 2D representation of cell defined in figure 2.1.

Figure 2.2 2D representation of sphere with organic matter.

15 Figure 2.3 2D representation of a Cell used in FSGP model.

2. Many of these representative but general cells are put together forming a layer of reservoir and linked to a well or well fracture. The thesis quantitatively describes these processes as well as clarifies the geological conditions under which a successful shale gas production could be expected in chapter 3. The arrangement of cells is in the same way as for conventional reservoir for the numerical solution.

Figure 2.4 Cells linked together forming a layer of reservoir.

3. Multiple layers of cells are then linked to a horizontal well through a hydraulic

fracture vertical fracture. The flow of gas is from one cell to another and then to

the well through the induced fracture. However, the model is based on number of

assumptions. Desorption of gas from the organic matter feed the matrix only and

do not contact the fractures directly. The matrix then feeds the gas to the

micro-fracture. Finally, it is assumed that gas flows out only through the fractures and

no gas flows out from the matrix directly. Figure 1.7 shows the complete

representation of the model proposed.

16 Figure 2.5 Shale formation is connected to a well through hydraulic fracture.

Chapter 3 describes the mathematical model derived for single phase flow of gas in 2D reservoir.

When the well is opened for production, the free gas will start flowing from the

micro-fractures to the vertical fracture and then to the horizontal well due to pressure

depletion. After certain amount of time, when the pressure in the cell depletes below the

critical desorption pressure, desorption of gas will start and feed gas to the

micro-fractures.

In document Modelling of gas production from tight shale formations: An innovative approach (sider 20-25)